Recovering hydrocarbons from subterranean zones typically involves drilling wellbores.
Wellbores are made using surface-located drilling equipment which drives a drill string that eventually extends from the surface equipment to the formation or subterranean zone of interest. The drill string can extend thousands of feet or meters below the surface. The terminal end of the drill string includes a drill bit for drilling (or extending) the wellbore. Drilling fluid, usually in the form of a drilling “mud”, is typically pumped through the drill string. The drilling fluid cools and lubricates the drill bit and also carries cuttings back to the surface. Drilling fluid may also be used to help control bottom hole pressure to inhibit hydrocarbon influx from the formation into the wellbore and potential blow out at surface.
Bottom hole assembly (BHA) is the name given to the equipment at the terminal end of a drill string. In addition to a drill bit, a BHA may comprise elements such as: apparatus for steering the direction of the drilling (e.g. a steerable downhole mud motor or rotary steerable system); sensors for measuring properties of the surrounding geological formations (e.g. sensors for use in well logging); sensors for measuring downhole conditions as drilling progresses; one or more systems for telemetry of data to the surface; stabilizers; heavy weight drill collars; pulsers; and the like. The BHA is typically advanced into the wellbore by a string of metallic tubulars (drill pipe).
Modern drilling systems may include any of a wide range of mechanical/electronic systems in the BHA or at other downhole locations. Such electronics systems may be packaged as part of a downhole probe. A downhole probe may comprise any active mechanical, electronic, and/or electromechanical system that operates downhole. A probe may provide any of a wide range of functions including, without limitation: data acquisition; measuring properties of the surrounding geological formations (e.g. well logging); measuring downhole conditions as drilling progresses; controlling downhole equipment; monitoring status of downhole equipment; directional drilling applications; measuring while drilling (MWD) applications; logging while drilling (LWD) applications; measuring properties of downhole fluids; and the like. A probe may comprise one or more systems for: telemetry of data to the surface; collecting data by way of sensors (e.g. sensors for use in well logging) that may include one or more of vibration sensors, magnetometers, inclinometers, accelerometers, nuclear particle detectors, electromagnetic detectors, acoustic detectors, and others; acquiring images; measuring fluid flow; determining directions; emitting signals, particles or fields for detection by other devices; interfacing to other downhole equipment; sampling downhole fluids; etc. A downhole probe is typically suspended in a bore of a drill string near the drill bit.
A downhole probe may communicate a wide range of information to the surface by telemetry. Telemetry information can be invaluable for efficient drilling operations. For example, telemetry information may be used by a drill rig crew to make decisions about controlling and steering the drill bit to optimize the drilling speed and trajectory based on numerous factors, including legal boundaries, locations of existing wells, formation properties, hydrocarbon size and location, etc. A crew may make intentional deviations from the planned path as necessary based on information gathered from downhole sensors and transmitted to the surface by telemetry during the drilling process. The ability to obtain and transmit reliable data from downhole locations allows for relatively more economical and more efficient drilling operations.
There are several known telemetry techniques. These include transmitting information by generating vibrations in fluid in the bore hole (e.g. acoustic telemetry or mud pulse (MP) telemetry) and transmitting information by way of electromagnetic signals that propagate at least in part through the earth (EM telemetry). Other telemetry techniques use hardwired drill pipe, fibre optic cable, or drill collar acoustic telemetry to carry data to the surface.
Directional drilling involves guiding a drill bit in order to steer a well bore away from the vertical. Directional drilling may be used to cause a well bore to follow a desired path to a formation that is away to one side of the drill rig. Measurement while drilling (MWD) equipment is used to relay to the surface information from a probe located downhole. The information can be used by the crew of the drill rig to make decisions as to how to control and steer the well to achieve a desired goal most efficiently. The information may, for example, include inclination and azimuth of a portion of the drill string that includes a downhole probe.
In some directional drilling applications, a drill bit is turned by a mud motor in the bottom hole assembly. The mud motor is driven by high pressure drilling mud supplied from the surface. While the drill bit is being driven by the mud motor, it is not necessary to drive the drill bit by rotating the entire drill string.
Steering is typically accomplished by providing a bent sub, which is a section of the drill string which bends through an angle as opposed to being straight. FIG. 1B shows an example bent sub 20 in which the bent sub turns through an angle theta. The bent sub is typically located close to the drill bit. The bend in the bent sub causes the drill bit to address the formation being drilled into at an angle. This angle is primarily determined by the degree of bend of the bent sub.
The direction in which the bent sub deviates from the longitudinal axis of the drill string is called the high side. High side identifies a direction projecting radially outwardly from the main longitudinal axis of the drill string in the direction to which the bent sub is bent. The direction in which the drill bit will progress when driven by the mud motor is determined primarily by the orientation of the drill bit. This orientation may be defined by a “tool face” which is a plane perpendicular to the axis of rotation of the drill bit. The path taken by a well bore can be steered by turning the drill string such that the direction in which the drill bit is facing is changed.
Directional drilling is generally started by drilling a vertical section of wellbore. At some point, the drill is operated so that the wellbore deviates from the vertical forming a curve or ‘dogleg’. The trajectory of the wellbore may change rapidly as a curve is formed in the wellbore. Allowing the wellbore to curve too tightly (forming a ‘micro-dogleg’) can cause problems. For example, casing may not fit easily through the micro-dogleg section. Repeated abrasion by the drill string at a micro-dogleg can result in worn spots in which the BHA may become lodged. Micro doglegs can also increase the overall friction of the drill string, resulting in increased potential for damage to the BHA.
Drillers require high quality timely information from downhole sensors to perform efficient and accurate directional drilling. Inaccurate or out-of-calibration information can result in a wellbore following a path that is inefficient and/or problematic. Mistakes in calibrating sensors can result in expensive consequences. There remains a need for ways to provide accurate telemetry information in directional drilling.